The present disclosure generally relates to a system and a method for determining uncertainty with a predicted wellbore position. More specifically, the system and method may determine a probability of an anticipated wellbore position being within a predetermined area.
To obtain hydrocarbons, a drill bit is driven into the ground surface to create a wellbore through which the hydrocarbons are extracted. Typically, a drill string is suspended within the wellbore, and the drill bit is located at a lower end of sections of drill pipe which form the drill string. The drill string extends from the surface to the drill bit. The drill string has a bottom hole assembly (“BHA”) located proximate to the drill bit.
Directional drilling is the steering of the drill bit so that the drill string travels in a desired direction. Before drilling begins, a well plan is established which indicates a target location and a drilling path to the target location. After drilling commences, the drill string is directed from a vertical drilling path in any number of directions to follow the well plan. Directional drilling may direct the wellbore toward the target location.
Further, directional drilling may form deviated branch wellbores from a primary wellbore. For example, directional drilling is useful in a marine environment where a single offshore production platform may reach several hydrocarbon reservoirs by utilizing deviated wells that may extend in any direction from the drilling platform. In addition, directional drilling may control the direction of the wellbore to avoid obstacles, such as, for example, formations with adverse drilling properties. Directional drilling may also enable horizontal drilling through a reservoir.
Moreover, directional drilling may correct deviation from the drilling path established by the well plan. Typically, the trajectory of the drill bit deviates from the trajectory established by the well plan due to unpredicted characteristics of the formations being penetrated and/or the varying forces experienced at the drill bit and the drill string. Upon detection of such deviations, directional drilling may return the drill bit back to the drilling path established by the well plan.
Known methods of directional drilling use a mud motor system or a rotary steerable system (“RSS”). For a RSS, the drill string is rotated from the surface, and downhole devices cause the drill bit to drill in the desired direction. A RSS is typically more expensive to operate than a mud motor system. For a mud motor system, the drill pipe is held rotationally stationary during a portion of the drilling operation while the mud motor rotates the drill bit. The toolface of the BHA is an angular measurement of the orientation of the BHA relative to the top of the wellbore, known as gravity tool face, or relative to magnetic north, known as magnetic tool face. For a mud motor system, rotating the drill string changes the orientation of the toolface of the bent segment in the BHA. To effectively steer the drill bit, the operator or the automated system controlling the directional drilling must determine the current location and position of the drill bit and the toolface orientation.
Data measured at the surface and/or measured downhole is used to determine the current location and position of the drill bit and the toolface orientation. For example, the current location and position of the BHA are determined using measurements of the inclination and the azimuth of the BHA, known as “D&I” measurements. A measurement-while-drilling (MWD) tool located in the upper end of the BHA obtains the D&I measurements. The MWD tool may have an accelerometer and a magnetometer to measure the inclination and azimuth, respectively. The toolface orientation is determined using a toolface sensor that may be connected to the mud motor or rotary steerable system. The toolface sensor may use an accelerometer, a gyroscope or other measuring device to determine an angle of the toolface. The toolface sensor is typically closer to the drill bit than the MWD tool.
The D&I measurements are obtained by static surveys made at various time or depth intervals. The operator or the automated system uses the estimated location and the estimated position to control the directional drilling. However, D&I measurements are typically obtained at a distance from the drill bit, such as, for example, tens of feet. The D&I measurements at this distance from the BHA may not be indicative of the actual D&I at the drill bit, and, accordingly, the estimated location and/or the estimated position of the drill bit may be inaccurate. The directional drilling may be compromised because of the inaccurate estimated location of the drill bit.
In addition, moving the drill bit to the drilling path established by the well plan may be difficult after deviation from the drilling path. Accordingly, accurately determining how to direct the drill bit to the course established by the well plan may make directional drilling more consistent and predictable relative to currently known systems.